Until this month, only one contract traded on an exempt commercial market was considered by the Commodity Futures Trading Commission (CFTC) to be a significant price discovery contract (SPDC). SPDCs are considered to perform significant price discovery functions, and the CFTC can require that specific position limits and position accountability standards be adopted for them. Seven more natural gas contracts have now joined that category.
In its April 27, 2010 meeting, the CFTC examined 23 natural gas contracts traded on two exempt commercial markets, the Intercontinental Exchange (ICE) and Natural Gas Exchange (NGX). It voted to designate seven ICE natural gas contracts as SPDCs. All of them are financially settled basis contracts that are priced at a differential between the New York Mercantile Exchange (NYMEX) settlement price for Henry Hub natural gas and the value of natural gas at other locations, specifically:
These seven now join the Henry Hub Financial LD1 Fixed Price contract traded on ICE, which the CFTC designated a SPDC last summer. As background, ICE operates as an exempt commercial market under the Commodity Exchange Act (CEA). Pursuant to amendments to the CEA in 2008, ICE is subject to certain regulatory obligations and CFTC oversight with respect to its markets in contracts that are designated by the CFTC as SPDCs. Thus, for each of these SPDC-designated seven contracts, ICE must adopt spot month position limits if trades in the contract are cleared. ICE also will have to adopt position accountability levels or position limits for the contracts for the non-spot months and all months combined and implement large trader position reporting for the contracts.
The CFTC is in the process of evaluating 16 electricity contracts and one refined petroleum contract to determine if any should be designated as SPDCs. CFTC staff has indicated that it will be presenting analysis and recommendations to the CFTC commissioners in one to two months.
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In a separate matter, on April 22, 2010, the CFTC issued an order settling charges against the San Diego Gas & Electric Company (SDG&E) for engaging in wash sales in natural gas futures contracts traded on NYMEX. Wash sales involve transactions with the intention to avoid taking a bona fide market position and are unlawful under CEA §4c(a). The CFTC found that SDG&E engaged in wash sales by placing simultaneous buy and sell orders for NYMEX natural gas contracts between January 26 and February 2, 2006, with instructions that the buy and sell orders be executed at or near the same price, and that the orders were in fact executed at or around the same price and time. SDG&E settled the charges without admitting or denying the CFTC’s findings. Under the settlement offer, the CFTC ordered SDG&E to cease and desist from violating CEA §4c(a), pay a civil monetary penalty of $80,000, and implement procedures to ensure that its trading on U.S. futures markets complies with the CEA, CFTC rules, and applicable exchange rules.
FERC recently applied and clarified principles it laid down in Order No. 679 governing available incentives for transmission projects in two orders, one involving California projects and the other in the Mid Atlantic region.
As background, Order No. 679 et seq. identifies ratemaking incentives available under Federal Power Act (FPA) §219 and requires applicants to tailor proposed incentives to the type of transmission investments being made and to demonstrate that proposals meet the requirements of §219. FERC allows applicants to seek incentives either in a request for declaratory order or a §205 rate proceeding, but applicants must demonstrate a nexus between the proposed incentives and the investment being made.
Order No. 679 provides an incentive-based return on equity (ROE), when justified, to all public utilities for new investments in transmission that benefit consumers by ensuring reliability or reducing the cost of delivered power by reducing congestion. Not every investment that increases reliability or reduces congestion qualifies for such an incentive. The “most compelling cases” for incentive-based ROEs are new projects with special risks or challenges, not routine investments made in the ordinary course of expanding the system to provide safe and reliable transmission service.
In the first order, FERC approved on rehearing a Southern California Edison base return on equity of 9.54 percent for three proposed transmission projects: the Devers-Palo Verde II Project, a $560-million project that consists of the construction of two major 500 kV transmission lines connecting Arizona to Southern California; the Tehachapi Transmission Project, $1.7-billion project distributed into 11 segments, which consists of more than 200 miles of 500 kV transmission line, approximately 10 miles of 220 kV transmission line, and three new substation facilities; and the Rancho Vista transmission substation project, a $200-million 500 kV substation project.
In a 2008 order, FERC had provided a zone of reasonableness for the ROE. The California Public Utilities Commission requested rehearing of the 2008 order and argued that the ROE was excessive. FERC denied the request for rehearing on April 15, 2010 and determined the base ROE by applying a discounted cash flow analysis to a proxy group of 14 companies, adjusting the base ROE for average yields on 10-year constant maturity U.S. Treasury bonds. The base ROE was supplemented by incentive adders of 125 and 175 basis points approved in 2008, bringing the total ROEs to 10.79 percent and 11.29 percent.
In the second order, FERC denied a request for rehearing of a 2009 order that granted PSE&G a ROE adder of 150 basis points in connection with PSE&G’s share of the Mid-Atlantic Power Pathway Project (MAPP Project), a regional transmission expansion plan approved by PJM involving PSE&G, Pepco Holding, Inc., Virginia Electric and Power Company, and Baltimore Gas and Electric Company. The issue on rehearing was whether PSE&G met its burden under FPA §219 and Order No. 679 to obtain transmission rate incentives.
FERC evaluated the risks associated with PJM cancelling the project, the numerous federal and state approvals needed, and the inability of PSE&G or another co-owner to get the necessary permits and siting approvals that could cause cancellation of the project. In light of these risks, FERC found that PSE&G demonstrated that a sufficient nexus existed between the requested incentives and the proposed project. FERC determined that “the MAPP Project will involve significant regulatory, siting and construction risks, and that PSE&G’s participation in that project will require a substantial investment in transmission facilities well over its average annual investment in recent years.” Additionally, FERC found that the 150 basis-point adder will improve PSE&G’s cash flows, which are taken into account in the financial metrics used to attract external funding. For these reasons, FERC affirmed its previous order and denied rehearing on these issues. It determined that PSE&G showed that the requested incentives were “tailored to address the demonstrable risks or challenges faced by the applicant.”
There is a sharp divide in comments in an ongoing rulemaking regarding determinations of “control” and “affiliation” market based rate and transfer of control proceedings. The Transmission Access Policy Study Group (TAPS) and other representatives of municipal and rural utilities accused the Electric Power Supply Association (EPSA) and Financial Investors Energy Group (FIEG) of seeking “modifications that would gut” the newly proposed rules.
The proposed rules are intended to simplify and clarify the approval process. For example, FERC has broad authority under §203 of the Federal Power Act to regulate and limit transfers of control and investments over $10,000,000 in public utility companies. Under current rules, FERC has granted a blanket approval for acquisitions of securities representing less than 10 percent of the voting shares in a public utility. An investor seeking to acquire a larger interest in a public utility must obtain specific approval from FERC.
The 10 percent threshold is also used to define a public utility’s affiliate group for market-based rate purposes under § 205 of the Federal Power Act. A company that owns less than 10 percent of the voting securities in a public utility is presumed not to have control and, consequently, not to be an affiliate. Since only affiliates are considered by FERC in evaluating a public utility’s market power, investments larger than 10 percent can adversely effect a utility’s application for market-based rate authority.
In 2008, EPSA filed a petition asking FERC to clarify the rules governing investors who purchase between 10 percent and 20 percent of a public utility’s voting securities. EPSA expressed concern that existing rules create uncertainty and discourage investment in energy infrastructure. Specifically, EPSA is worried that, because holding companies often invest beyond the 10-percent threshold in several companies, technical compliance by public utilities with the affiliate rules is often impractical. A public utility company may not be aware of its investors’ other investments; it may not even know who its affiliates are.
In response to the petition, FERC proposed new rules providing blanket authorization for acquisitions of 10 – 20 percent of a public utility’s voting securities if the investor will certify that it does not and will not attempt to control the public utility. Further, FERC would disregard, in its market-based rate decisions, reporting requirements for affiliates falling within that blanket authorization.
To qualify under either part of this proposal, an investor will be required to submit a standardized form called an “Affirmation in Support of Exemption from Affiliation Requirements.” The form asks for basic information about the transaction and the investor’s existing utility holdings. Additionally, a senior executive officer must certify that the “acquisition was not for the purpose, or with the effect, of changing or influencing control over the public utility” and agree to several conditions limiting the investor’s control over its investment.
Commenting on the proposal, EPSA suggested that FERC should allow public utility companies, rather than investors, to affirm the lack of control. FIEG proposed a rule that does not require certification by an investor’s officer. The TAPS Group argues that EPSA’s proposal would “frustrate or defeat” FERC's goals and that FIEG is trying to shield officers and directors from liability and responsibility. Until final rules are promulgated, the dispute will remain unresolved. Nonetheless, it appears likely that some form of FERC’s proposal will be implemented that will simplify and encourage investment in energy infrastructure projects while clarifying regulatory and reporting obligations.
FERC recently ruled on proposed revisions submitted by ISO New England (ISO-NE) and the New England Power Pool Participants Committee (Filing Parties) in February 2010 (Rules Changes Filing) to its continually evolving and controversial Forward Capacity Market (FCM) pursuant to which resources compete in an annual Forward Capacity Auction (FCA) on a three-year-forward basis.
While developed in a stakeholder process, the proposed revisions were opposed by the entire generation sector. The proposed revisions include:
Both the New England Power Generators Association and PSEG Energy Resources & Trade LLC filed complaints contesting certain aspects of the proposed revisions in the Rules Changes Filing.
In its April 23, 2010 Order, FERC found certain aspects of the Rules Changes Filing to be just and reasonable, but also stated that the remainder of the filing may be unduly discriminatory or preferential, not just and reasonable or otherwise unlawful. FERC accepted the Rules Changes Filing to allow market rules to be in place for the August 2010 FCA. FERC, however, required the Filing Parties and parties protesting the revisions to make further arguments regarding the challenged aspects of the Rules Changes Filing in a paper hearing, by submitting their briefs to FERC. This proceeding consolidates the two complaint proceedings as well. The issues that FERC will consider in the paper hearing are:
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Authors and Editors:
Ronald N. Carroll
Thomas McCann Mullooly
Trevor D. Stiles
John T. Dunlap